Appraiser’s FAQ on Minerals Valuation

During a recent webinar that I was one of 3 presenters, several questions came up about valuation.  The subject of Mineral Rights Valuation cannot be squeezed into a simple 2 hour webinar. It’s simply too big a subject. But post-presentation comments pointed some areas where additional information is available.  I try to answer those questions in this section

FAQ 1 – Where can I get published cap rate data?

Published capitalization rates for mineral interests are annually presented by the Society of Petroleum Evaluation Engineers (SPEE) aka   These are based on surveys with companies, bankers, and consultants. I was asked to participate this year as a consultant.

FAQ 2 – What approaches to value are applicable?

Valuation can be performed by a number of methods, and to limit the discussion to owner interests (royalty interests as opposed to working interests), the cost approach is not applicable. Wellhead equipment belongs to the operator and should not be included in the valuation.  The mineral owner is a leased fee interest and has no executive control over the extraction of mineral rights.

The sales approach is the most basic approach for valuing non-producing property, but can be applied to producing property. It is difficult in that state as you must compare apples to apples.  Thus, the production history and percent of the drilling unit produced must be taken into account and adjusted accordingly.  It is usually a weak sister to the income approach when trying to apply sales to producing property.

The income approach can be used in several ways.  One is the simple income multiplier.   The basic 3 x value multiple is used in many areas and has been for many years. A basic variation on that would be to total up the previous 36 months of production and say that equals the value.  The problem there is that in the case of unconventional wells, the wells deplete much faster than the conventional vertical well, therefore, the first 3 years of production may account for 80% of the total production. Few buyers would want to pay that unless there were additional potential for wells to be developed in that drilling unit.

Remember that an interest in states with pooling or under a pooling provision in a lease, are subject to all the pool being developed at some point.  Predicting when it occurs is not really possible, but I typically look at the estimated life of the well  for guidance and again, well life can be short.  The general development pattern is a pool will have from 4 to 12 wells, often 6-8.  A well is drilled to hold the leases (pooled) and later the operator may drill 2 to 4 more on a single pad. They may develop more than one unit at a time, with “cross section” wells – part in 2 or more units.

Multipliers can be used with undeveloped property if lease amounts are known. Landmen often estimate the market value at 3 x the bonus.  (A lease has a signing bonus, and a time limit, but if production is found, the royalty is paid and the lease is extended as long production exists. A “delay rental” is paid annually unless the lease is a “paid up” lease)

Income discounting also can be applied, such as a sinking fund method like Inwood or Hoskold’s premise. These normally are applied for quarries, frac sand pits, or production where the annual level of income is more predictable and not subject to serious decline.

Finally, a valuation can be based on reserves tends to be the most accurate.  Important to that is the ESTIMATOR.  An appraiser should not be the estimator, no more than an appraiser would want to run their own timber cruise. Leave that to other professionals and reduce your liability.  What does an estimator do?  They will look at existing wells in the unit, estimate the amount of remaining reserves based on a decline curve, and that figure (the remaining reserves) is used to extrapolate the remaining production in the entire unit.

Example – Say 2 wells have been drilled and 8 wells can exploit the entire section (unit) Say those two wells have each produced 2 BCF (billion cu. ft.) and remaining production is 4 BCF.  There are 6 undeveloped sites to be drilled in the future.  Reserves that are not produced must be discounted for the risk of drilling, price risk, and time-value of money.  The SPEE produces tables that generally indicates producing wells are estimated at 100% of the reserves, and PUD (proven production but undeveloped) wells are valued at 60% of their reserves.  [an intermediate step is “behind pipe” valued at 80%].

Thus, in the example, 6 wells x 4 BCF (using the existing wells as a proxy for the PUD wells) x 60% = 14.4 BCF PLUS the two wells remaining reserves (4 x 2 = 8 BCF less 4 BCF = 4 BCF remaining, for a total of 18.4 BCF RISKED Reserves.

What is the value?  Acquisitions and Divestitures are made weekly, but finding those sales may prove difficult and generally can be found on line or in trade magazines – or EDGAR filings with the SEC.  Say that ABC oil is selling an old existing gas field to XYZ Corp.  It estimates 10 BCF remaining and sold for $11.5 Million…or $1.15 per MCF (gas is sold in 1000 cu. ft).  In general, this is roughly one-third the current market price.  If gas is selling for $3.45 per MCF, then the price typically will be near $1.15/MCF.  Dr. John Baen, a mineral expert recommends the one third current market price as a rule of thumb.

Discounted Cash Flow can be applied – basically by predicting the average annual production and price. I prefer the method above, but tend to run both as a check on the reasonableness of the estimate.

So, in summary, you must account for the producing wells and the future wells that may be drilled.  More information can be found in my book, “The Appraisal of Mineral Rights“.

FAQ 3 – What about frac sand mines?

Frac sand is used to prop open the pore spaces during the frac process. It’s price relates to demand. But the methods applied are those of mine valuation.  The volume of exploitable materials must be calculated, and a value placed on that volume.  Again, an estimate of the size of the mine is necessary to put a value on a frac pit.

FAQ 4 – Why was the discussion of the Mayflower pipeline rupture included?

I suspect that was a question from a geologist, not an appraiser.  But the reason was to demonstrate that such incidents have real impact on property values. In the case study, the pipeline repaired the damage, but a stigma remains as the homes were not selling for the pre-disaster prices, except to sell to the pipeline company (which bought about half the homes in the subdivision and took two homes down that were too damaged to repair.

FAQ 5 – Does fracking cause serious air and water pollution?

Not in my experience.  The EPA recently released a study of 950 professional papers and studies of water quality and concluded no impact was notable.  Fracking is well below the fresh water table and most pollution is from surface water handling such as spilled fuel trucks, leaks, or a reserve pit being overflowed by a flood.  More studies can be found on the USGS site linking various studies.

FAQ 6 – Can a geologist provide an appraisal of minerals without a state certification? Can an appraiser provide an appraisal if they are not also a geologist or engineer?

That would be a legal matter, but in a mandatory state, most appraisers must have some sort of license when setting values.  In some cases engineers avoid this with the substitution of the words “Net Worth” for “Net Value”. And a court can allow the testimony of any person it deems qualified under the Daubert Rule.  But if a geologist is asked for a value, then they need to be qualified before the judge as an expert in valuation…either by training or certification.

An appraiser can engage the services of an expert (geologist or engineer) and use that information to develop an appraisal. This is the estimator function described above in FAQ 2.  This reduces the liability of the appraiser and although I can run decline curves and am a registered geologist, I prefer to sub that work out to someone else.

FAQ 7 – More on Leasing Issues

Leasing is basically well under way before the public realized the complexity of the issue. The oil company has a decided advantage in the process, especially in non-state pooled areas, where they put together the pool themselves, thus do not have to approach the state regulators for permission to create the pool.  A good source of information for lease issues is the National Association of Royalty Owners (NARO) or one of their state chapters.